In the production of oil from underground formations, once a well has been drilled it is often necessary to fracture the underground formation to increase the exposure the well has to the surrounding formation. In many wells, this is accomplished through the use of fracturing fluids, commonly referred to as “frac fluids”, which are pumped into the well bore at a sufficient rate and pressure to increase the pressure downhole to a value in excess of the fracture gradient of the formation rock. This high pressure causes the formation to crack such that a multitude of fracture lines will extend radially from the well and thus, allow the frac fluid and any proppant to enter the fracture lines and thereby flow into the formation. Upon releasing the surface pressure, the frac fluids (without proppant) will flow back to well where they are pumped out of the well for re-processing and/or disposal.
Frac fluids are often comprised of a hydrocarbon carrier liquid together with proppants and various phosphate derivatives that act as gelling agents to assist in carrying the proppants within the induced fractures. That is, the gelling agents generally act to temporarily increase the viscosity of the frac fluid to facilitate the transport of proppants into the fractures. A well-known method for gelling hydrocarbons uses a combination of a phosphate ester backbone combined with a metal activator/cross linking agent and breaker system. Examples of these systems are described in various patents. For example, U.S. Pat. No. 4,781,845; U.S. Pat. No. 4,316,810; U.S. Pat. No. 4,174,283; U.S. Pat. No. 4,200,539; U.S. Pat. No. 4,200,540; and U.S. Pat. No. 4,622,155 describes frac fluids that use an aluminum salt and an alkyl phosphate ester. U.S. Pat. No. 3,505,374 and U.S. Pat. No. 5,417,287 describe similar systems using iron as the cross linking agent.
As noted, after frac fluids have been “broken” (i.e. the temporarily induced viscosity is relaxed) and have otherwise served their purpose to fracture the formation, they are flowed back from the well and recovered. Depending on the frac fluid system, many frac fluids will be ultimately combined with crude oil for sale to refineries. Unfortunately, these flow back fluids contain residual oil-soluble phosphate esters that, unless substantially removed from the residual oil, can lead to significant downstream issues during subsequent oil processing at a refinery. For example, when a crude oil is combined with the flow back fluid and then enters an oil refinery, it may be heated in a refinery tower to approximately 340° C., which causes ester hydrolysis and the formation of lower molecular weight phosphorus compounds that vaporize and condense in the upper stages of the tower. The phosphorus compounds in the crude oil may cause fouling in the tower by restricting flow due to the buildup of a polymeric deposit, typically composed of carbon, hydrogen, phosphorus, nitrogen, and copper/nickel. Flow restrictions decrease the efficiency of the tower and will ultimately lead to a shutdown to remove the contaminants. High levels of phosphorus compounds in the crude oil can also lead to fractionation problems as foulant accumulates in pre-flash towers, which, as above, will require periodic equipment shutdowns as high phosphorus compound levels may cause an increase in furnace Tube Metal Temperatures (TMT). As is well known, any equipment shutdowns are costly to oil refineries.
As a result of the problem of the fouling of oil refinery equipment by phosphorus derivatives, the Canadian Association of Petroleum Producers has put an upper limit specification of 0.5 ppm volatile phosphorus in crude oil, where volatile phosphorus is defined as the phosphorus found in the oil fraction removed by a single plate ASTM D86 distillation (i.e. the phosphorus concentration in the distillate fraction of crude oil collected from the initial boiling point (IBP) to 250° C.). Total phosphorous includes all phosphorous compounds that do and do not meet the above definition. Currently, the high-volatile phosphorus gellant technology commonly used in the manufacturing of frac fluids can result in volatile phosphorus values greater than 100 ppm in initial flow-back.
In general, a typical oil or gas well fracture service will use approximately 100 m3 of frac fluid per fracture per well. In addition, there are trends within the industry to use substantially larger volumes of fracturing fluids as a result of the exploitation of deeper hydrocarbon reservoirs and new fracturing technologies. Under normal activity levels in Western Canada, there is an estimated total volume of flow-back fluids of 400,000 m3 per year. The market in the United States is estimated at 5,000,000 m3 of flow back fluids per year. As a result, due to the imposed limits on volatile phosphorus in crude oil, oil companies generally have a need for a solution to reduce volatile phosphorus in crude oil. Various solutions to reduce volatile phosphorus include using a non-phosphorus based oil gellant; using a low-volatiles phosphorus based oil gellant; using water-based fracing; and removing volatile phosphorus from frac fluid returns.
Non-Phosphorus Based Oil Gellants
A review of the prior art reveals that various non-phosphorus based oil gellants have been in existence for some time, as described in U.S. Pat. No. 3,539,310 and U.S. Pat. No. 2,618,596. However, non-phosphorus based oil gellants are generally not utilized as the breaking of non-phosphorus based oil gellants tends to be inconsistent. More specifically, it can be difficult to obtain reproducible gels under field conditions where water content and the variability of oil chemistry cause unpredictable changes in the gel properties and breaking times.
Low-Volatility Phosphorus Based Oil Gellants
A review of the prior art reveals that various low volatility phosphate ester systems have been proposed as oil gellants as described in U.S. Patent Application 2007/0032387 and U.S. Patent Application 2007/0173413. These low phosphate gelling systems still contain phosphorus that can lead to the oil having a volatile phosphorus content greater than 0.5 ppm. These systems may also have other metal ions present that cause the gellation to occur which can lead to other issues such as the need for the removal of that metal ion. Moreover, such systems will also typically have a higher cost than the high volatility phosphorus gelling technologies.
Water-Based Fracturing Fluids
Water based fracturing technology that does not involve phosphorus is currently in use in the oil industry. This method does not contribute to refinery equipment fouling based on phosphorus derivatives. However, water-based fracing is limited by the effects of water in the well as within many formations even small amounts of water can cause serious damage to the formation by causing the migration of fines or the swelling of water sensitive clays in the formation such that formation may be made unusable when it is fraced with water. As well, oil-based fracing fluids are typically easier to clean up than water-based fracing fluids in dry or non-water containing formations.
Processes for Removing Phosphorus from Fracturing Fluid Returns
There are several technologies in existence for the removal of phosphorus from frac fluid returns. For example, one such technology as stated in the Phosphorus in Crude (August 2005) document located on the Canadian Crude Quality Technical Association (CCQTA) website (http://www.ccqta.com/phosphorus.asp), entitled “Volatile Phosphorus Remediation”, uses a catalytic treatment process to extract phosphorus and other contaminants from frac fluid flow back. Other references describe various chemical treatments available to remove phosphorus from frac fluid flow back. For example, U.S. Pat. No. 6,207,612 discloses a method to develop an adsorbent media comprised of alumina with minor amounts of calcia and magnesia to remove phosphate and metal contaminants from hydrocarbon oil.
However, a review of the prior art reveals that there continues to be a need for a method for the effective removal of phosphorus from frac fluid flow back and crude oil and particularly an effective method of using acid-activated clays. While the prior art shows various processes for making and utilizing acid-activated clays for bleaching vegetable oils are described in U.S. Pat. No. 1,397,113; and other uses as described in U.S. Pat. No. 1,579,326; U.S. Pat. No. 5,008,227; U.S. Pat. No. 6,365,536; U.S. Pat. No. 2,090,741; U.S. Pat. No. 6,489,260; and U.S. Application 2008/0223756, the prior art is silent with respect to the effective removal of phosphorous from fracturing fluids using clays. In addition, while U.S. Pat. No. 4,124,492 and corresponding CA Patent No. 1,071,132 teach a process for reclaiming useful hydrocarbon oils from waste oil, specifically crankcase oil and used diesel lubricating oil, using a treatment of acid activated clay at a high temperature, after the waste oil has been treated with isopropanol or N-propanol, to clarify the oil, these patents are also silent with respect to the effective removal of phosphorous from fracturing fluids using clays.
More specifically, therefore, there has been a need for the effective use of acid-activated clay for the removal of volatile phosphorus from broken frac fluids and crude oil with high volatile phosphorus content. While acid-activated clay is known as a bleaching agent and is a known method for removing coloring materials and odor causing compounds from vegetable oils, the prior art does not teach or support a process for utilizing such clays with petroleum oils and specifically, petroleum oils that have been contaminated with phosphorus from frac fluid flow back.